1. Field of the Invention
The field of the invention is fluidized catalytic cracking in general and catalyst stripping in particular.
2. Description of Related Art
Catalytic cracking is the backbone of many refineries. It converts heavy feeds into lighter products by catalytically cracking large molecules into smaller molecules. Catalytic cracking operates at low pressures, without hydrogen addition, in contrast to hydrocracking, which operates at high hydrogen partial pressures. Catalytic cracking is inherently safe as it operates with very little oil actually in inventory during the cracking process.
There are two main variants of the catalytic cracking process: moving bed and the far more popular and efficient fluidized bed process.
In the fluidized catalytic cracking (FCC) process, catalyst, having a particle size and color resembling table salt and pepper, circulates between a cracking reactor and a catalyst regenerator. In the reactor, hydrocarbon feed contacts a source of hot, regenerated catalyst. The hot catalyst vaporizes and cracks the feed at 425 C.-600 C., usually 460 C.-560 C. The cracking reaction deposits carbonaceous hydrocarbons or coke on the catalyst, thereby deactivating the catalyst. The cracked products are separated from the coked catalyst. The coked catalyst is stripped of volatiles, usually with steam, in a catalyst stripper and the stripped catalyst is then regenerated. The catalyst regenerator burns coke from the catalyst with oxygen containing gas, usually air. Decoking restores catalyst activity and simultaneously heats the catalyst to, e.g., 500 C.-900 C., usually 600 C.-750 C. This heated catalyst is recycled to the cracking reactor to crack more fresh feed. Flue gas formed by burning coke in the regenerator may be treated for removal of particulates and for conversion of carbon monoxide, after which the flue gas is normally discharged into the atmosphere.
Catalytic cracking is endothermic, it consumes heat. The heat for cracking is supplied at first by the hot regenerated catalyst from the regenerator. Ultimately, it is the feed which supplies the heat needed to crack the feed. Some of the feed deposits as coke on the catalyst, and the burning of this coke generates heat in the regenerator, which is recycled to the reactor in the form of hot catalyst.
Catalytic cracking has undergone progressive development since the 40s. The trend of development of the FCC process has been to all riser cracking and zeolite catalysts.
Riser cracking gives higher yields of valuable products than dense bed cracking. Most FCC units now use all riser cracking, with hydrocarbon residence times in the riser of less than 10 seconds, and even less than 5 seconds.
Zeolite based catalysts of high activity and selectivity are now used in most FCC units. These catalysts work best when coke on the catalyst after regeneration is less than 0.1 wt %, and preferably less than 0.05 wt %.
To regenerate FCC catalysts to low residual carbon levels, and to burn CO completely to CO2 within the regenerator (to conserve heat and minimize air pollution) many FCC operators add a CO combustion promoter to the catalyst or to the regenerator.
U.S. Pat. Nos. 4,072,600 and 4,093,535, which are incorporated by reference, teach use of combustion-promoting metals such as Pt, Pd, Ir, Rh, Os, Ru and Re in cracking catalysts in concentrations of 0.01 to 50 ppm, based on total catalyst inventory.
As the process and catalyst improved, refiners attempted to use the process to upgrade poorer quality feeds, in particular, feedstocks that were heavier, and had more metals and sulfur.
These heavier, dirtier feeds pushed the regenerator, and exacerbated four existing problem areas in the regenerator, sulfur, steam, temperature and NOx. These problems will each be reviewed in more detail below.
SULFUR
Much of the sulfur in the feed ends up as SOx in the regenerator flue gas. Higher sulfur feed, and complete CO combustion in the regenerator, increase the SOx content of the flue gas. Some attempts were made to minimize the amount of SOx discharged to the atmosphere by including catalyst additives to capture SOx in the regenerator. These additives pass with the regenerated catalyst back to the FCC reactor where the reducing atmosphere releases the sulfur compounds as H2S. Suitable agents are described in U.S. Pat. Nos. 4,071,436 and 3,834,031. Use of cerium oxide for this purpose is shown in U.S. Pat. No. 4,001,375.
Unfortunately, the conditions in most FCC regenerators are not the best for SOx adsorption. The high temperatures in modern FCC regenerators (up to 870 C. (1600 F.)) impair SOx adsorption. One way to minimize SOx in flue gas is to pass catalyst from the FCC reactor to a long residence time steam stripper, as in U.S. Pat. No. 4,481,103 Krambeck et al which is incorporated by reference. This process steam strips spent catalyst at 500-550 C. (932 to 1022 F.), to remove some undesirable sulfur- or hydrogen-containing components, but considerable capital expense is involved.
STEAM
Steam is known to cause catalyst deactivation. Steam is not intentionally added, but is invariably present, usually as adsorbed or entrained steam from steam stripping or catalyst or as water of combustion formed in the regenerator.
Poor stripping leads to a double dose of steam in the regenerator, first from the adsorbed or entrained steam and second from hydrocarbons left on the catalyst due to poor catalyst stripping. Catalyst passing from the FCC stripper to the regenerator contains hydrogen-containing components, such as coke or unstripped hydrocarbons adhering thereto. This hydrogen burns in the regenerator to form water and cause hydrothermal degradation.
U.S. Pat. No. 4,336,160 to Dean et al, which is incorporated by reference, attempts to reduce hydrothermal degradation by staged regeneration. However, the flue gas from both stages of the regenerator contains SOx which is difficult to clean. It would be beneficial, even in staged regeneration, if the amount of water precursors present on stripped catalyst was reduced.
Steaming is more of a problem as regenerators get hotter. Higher temperatures accelerate the deactivating effects of steam.
TEMPERATURE
Regenerators are operating at higher temperatures. This is because most FCC units are heat balanced, that is, the endothermic heat of the cracking reaction is supplied by burning the coke deposited on the catalyst. With heavier feeds, more coke is deposited on the catalyst than is needed for the cracking reaction. The regenerator runs hotter, so the extra heat may be rejected as high temperature flue gas. Many refiners limit the amount of resid or high CCR feeds to that amount which can be tolerated by the unit. High temperatures are a problem for the metallurgy of many units, but more importantly, are a problem for the catalyst. In the regenerator, the burning of coke and unstripped hydrocarbons leads to much higher surface temperatures on the catalyst than the measured dense bed or dilute phase temperature. This is discussed by Occelli et al in Dual-Function Cracking Catalyst Mixtures, Ch. 12, Fluid Catalytic Cracking, ACS Symposium Series 375, American Chemical Society, Wash., D.C., 1988.
Some regenerator temperature control is possible by adjusting the CO/CO2 ratio in the regenerator. Burning coke partially to CO produces less heat than complete combustion to CO2. However, in some cases, this control is insufficient, and also leads to increased CO emissions, which can be a problem unless a CO boiler is present.
The prior art also used dense or dilute phase regenerator heat removal zones or heat-exchangers remote from, and external to, the regenerator to cool hot regenerated catalyst for return to the regenerator. Such approaches help, but we wanted to reduce the amount of unstripped hydrocarbons burned in the regenerator, rather than deal with unwanted heat release in the regenerator.
NOX
Burning nitrogenous compounds in FCC regenerators has long led to creation of minor amounts of NOx emitted with the regenerator flue gas, or associated with a downstream CO boiler. Usually these emissions were not much of a problem because of relatively low temperatures.
Many FCC units now operate at higher temperatures, with a more oxidizing atmosphere, and use CO combustion promoters such as Pt. These changes in regenerator operation which reduce CO emissions, usually increase nitrogen oxides (NOx) emissions. It is difficult in a catalyst regenerator to completely burn coke and CO in the regenerator without increasing the NOx content of the regenerator flue gas, so NOx emissions are now frequently a problem. Higher regenerator temperatures, due in part to burning of potentially strippable hydrocarbons in the regenerator contributes to the NOx problem.
It would be beneficial if a better stripping process were available which would increase recovery of valuable, strippable hydrocarbons. There is a special need to remove more hydrogen from spent catalyst to minimize hydrothermal degradation in the regenerator. It would be further advantageous to remove more sulfur-containing compounds from spent catalyst prior to regeneration to minimize SOx in the regenerator flue gas. Also, it would be advantageous to have a way to reduce to some extent regenerator temperature.
Although much work has been one on better stripping designs, there are still many shortcomings. We realized that the most significant problem was trying to achieve efficient stripping in a bubbling dense bed.
Although it might seem easy to increase the superficial vapor velocity in a stripper, by increasing the stripping steam rate, and improve stripping, in practice this is not possible. Increasing the stripping steam usually improves stripping, but in many units much of the increased stripping steam enters the regenerator. Stripping improves because of better settling or deration of spent catalyst within or just above the stripper.
We have now found a way to achieve better stripping of coked FCC catalyst. Our solution not only improves stripping, and increases the yield of valuable liquid product, it reduces the load placed on the catalyst regenerator, minimizes SOx emissions, and permits processing of more difficult feeds. Regenerator temperatures can be increased, reduced, or maintained constant while processing worse feeds, while the amount of hydrothermal deactivation of catalyst in the regenerator can be reduced.
We were able to overcome one significant deficiency of current spent catalyst strippers by correcting a mass flow problem peculiar to annular catalyst strippers disposed about a riser reactor. The problem was that one side of the stripper, the side opposite the stripped catalyst outlet line to the regenerator, was relatively dead or stagnant. Mass flow through the stripper was primarily down one side, with much of the spent catalyst passing, or bypassing, from the top of the annular stripper down one side to the stripped catalyst outlet. The catalyst flow on the other side of the stripper, i.e., on the side farthest from the stripped catalyst outlet, catalyst flow was relatively stagnant. The large "dead zone" in the base of the stripper on the side opposing the outlet, tended to make the area above it relatively dead, so that a large portion of the active volume of the stripper did little or no productive stripping. In some units, up to 20% of the stripper volume was "dead", or had a catalyst residence time at least twice as long as the average catalyst residence time in the stripper. This reduction in active, or effective, stripper volume could increase delta coke by 5% or more, with most of this coke being hydrogen rich strippable hydrocarbons.
We discovered a way to eliminate the dead zone using a catalyst transfer means. We were also able to conduct additional stripping in the transfer means, and even achieve multiple stage stripping in an annular stripper, preferably by adding baffling.